NATURAL GAS

If there are "monster wells" dwelling in the Marcellus Shale, count Cabot Oil & Gas Corp. among those trying to capture one.

In December, the Marcellus specialist unveiled its largest operation yet: an attempt to drill 10 horizontal wells from a single surface point. The firm billed it as a tour de force of efficiency with techniques and technologies that showed the edge of industry's reach into shale rock.

And by Cabot's rendering, the result was potentially monstrous. Doing it the traditional way would have cost $6 million more, the company said. Savings like that, applied across the Marcellus, could have enormous implications for profits, production and reserves.

But are these hyper-productive wells visions of the future or flashes in the pan?

There's no question that the nip-and-tuck mentality has spread. In 2013, faced with a second year of weak natural gas prices, oil and gas companies continued to cut costs and coax fossil fuels out in new ways. Phrases like "manufacturing-style development," "harvest mode" and "managed shale" became industry staples, while the "land-grab" era took on the past tense.

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"The idea of drill a well, go to another well, drill a well, go to another well, has evaporated," said Greg Powers, Halliburton Co.'s vice president of technology. "People drill multiple wells from a pad now ... our foresight was, 'make this like factory production for our customers."

Today the leading service companies, including Halliburton, routinely apply the factory approach. And for the near term, the proof appears to be in the pudding.

All six major shale basins will be more productive this month than they were a year ago, the Energy Information Administration recently reported. None advanced more than the Marcellus, where the average rig is on track to produce 20 percent more gas from a new well than it did a year ago. EIA launched the productivity report last fall to track the most important shale basins' success at staving off decline (EnergyWire, Oct. 22, 2013).

Among them, the Marcellus may represent the toughest stress case. Natural gas prices have spiked this winter, but for most of the last two years, spot prices tracked below $3, and then $4, per million British thermal units. Even with the current swoon, few analysts see prices staying above $4 per MMBtu anytime soon.

That has stanched gas production in many gas plays, but in the Marcellus, the low-cost resource of record, it forced a Spartan focus on efficiency.

"The Marcellus has become a monster," Thomas Driscoll, an analyst with Barclays Capital Inc., wrote in November 2013. "Marcellus gas production has doubled in the past 2 years to nearly 13 [billion cubic feet per day] -- and it shows no signs of slowing down."

It may end up holding prices down, Driscoll worried.

"If the Marcellus continues to grow at recent rates we fear that U.S. gas prices are more likely to fall short of $4 than to average more than $4 on long term natural gas prices," he said.

Another possibility: The Marcellus is preparing to flame out.

That's a real concern for David Hughes, a fellow at the Post Carbon Institute who worked at the Geological Survey of Canada for 30 years. Among his focus areas: unconventional gas.

"There may be small, incremental further gains in terms of reducing the cost of wells, but I think the biggest gains have already been had, in essence," he said. "The writing's on the wall. It's only a question of time before they become saturated with wells and drilling has to move out into poorer-quality parts of the reservoir."

Hughes admitted that productivity has been rising impressively, but he said companies tend to start at the hottest nodes of a play, and later nodes can't keep up.

With shale in particular, the descent can be steep. He claimed that in the Haynesville, production rates peaked in 2010 -- within two years of the industry developing it.

"I think the Marcellus is getting pretty close to the peak in [total] production," said Hughes, who noted that Pennsylvania will soon release fresh numbers. "When the data comes out, we can see what really happened. I wouldn't be surprised to see a peak in the Marcellus this year, maybe next year at the latest."

Asset vs. liability

But for the Marcellus' largest producers, productivity is a selling point to investors -- not an existential risk.

Take Southwestern Energy Co., which plans to spend $110 million less in the Marcellus this year while producing 60 percent more in the play. Or Range Resources Corp., which wants to raise production from its "super-rich" Marcellus wells by 20 percent this year.

Even Chesapeake Energy Corp., the country's second-largest gas producer, which is now emphasizing liquids, is in on the act. In the northern Marcellus, Chesapeake hopes to drill more than 80 percent of its wells from pre-existing pads.

Behind the Marcellus' growth is a grab bag of technologies and techniques. Pad drilling is among the most prevalent, and it appears to be getting more productive. George Stark, a Cabot spokesman, said the company averaged six wells a pad -- that is, six lateral wells drilled from a single vertical well -- in recent years. "Going to 10 was really taking it to the next level," he said.

As recently as 2011, pad drillers in the Marcellus rarely used more than three wells per pad, according to a fact sheet by Pennsylvania State University's College of Agricultural Sciences. Today, three-well pads are behind the curve -- and the frontier is 10 or more.

A number of other tools can be described in terms of a tree taking root. Operators are stretching the roots farther out. They're running them in tight parallels where possible. They're growing the roots faster. They're placing more trees on the same space.

To Pete Stark, senior research director for upstream research at IHS, it looks like the early stages of shale's "manufacturing" era.

"What we're finding is that in the early stages of improving performance in the shale gas or tight gas plays ... definitely there's a direct relationship of longer laterals, more frac stages, with higher initial productivity and higher reserves," he said.

Foggy horizon

One lingering question: How long can you nip and tuck before a breakthrough technology is needed?

In October, Dan Dinges, Cabot's chairman, president and CEO, was asked how much efficiency could improve in the next few years. He said Cabot would extend laterals and fire more "stages" of water at the rock.

"But it's not going to be as aggressive of an increase as you have seen in the past. By industry as a whole, I might add," he said.

Last month, Steven Mueller, Southwestern Energy's president and CEO, said he doesn't expect the Marcellus' torrid growth to last.

"Once Marcellus gets up to a certain point, it will slow down. It won't be growing-60-percent-a-year type thing," he said at the BMO Unconventional Resource Conference.

Beyond that, the technological horizon gets foggier. But many say that a near-term goal is to aim the laterals better while underground. Too often, the thinking goes, a shale has wrinkles and creases that keep the lateral from staying in it -- or hitting its juiciest parts.

Late last year, Halliburton unveiled CYPHER, a software package meant to "learn" a shale with each drilling attempt and increase the chances of hitting the money spots. And Schlumberger Ltd. has touted drill bits that turn more carefully underground, busting a more accurate hole for the eventual frac job.

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